Methods and apparatus for determining seismic streamer array geometry and seismic sensor response

ABSTRACT

A method for marine seismic surveying includes determining at least an initial depth of a plurality of spaced apart seismic sensors on streamers towed in a body of water. The sensors each include a substantially collocated pressure responsive sensor and motion responsive sensor. A ghost time delay is determined for each sensor based on the at least an initial depth. Seismic signals detected by each motion responsive sensor and each pressure responsive sensor are cross ghosted. The at least initial depth is adjusted, and the determining ghost time delay and cross ghosted seismic signals are repeated until a difference between the cross ghosted motion responsive signal and the cross ghosted pressure responsive signal falls below a selected threshold. Other embodiments, aspects and features are also disclosed.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application is a continuation of U.S. patent applicationSer. No. 13/274,995, filed Oct. 17, 2011 by Guillaume Cambois. U.S.patent application Ser. No. 13/274,995 is a continuation-in-part of U.S.patent application Ser. No. 12/229,847, filed Aug. 27, 2008 by GuillaumeCambois. The disclosures of the aforementioned patent applications arehereby incorporated by reference.

BACKGROUND OF THE INVENTION

Field of the Invention

The invention relates generally to the field of marine seismicsurveying. More particularly, the invention relates to methods forcorrecting marine seismic sensor array response for variations in arraygeometry during operation.

Background Art

Marine seismic surveying systems are used to acquire seismic data fromEarth formations below the bottom of a body of water, such as a lake orthe ocean. Marine seismic surveying systems typically include a seismicvessel having onboard navigation, seismic energy source control, anddata recording equipment. The seismic vessel is typically configured totow one or more streamers through the water. At selected times, theseismic energy source control equipment causes one or more seismicenergy sources (which may be towed in the water by the seismic vessel orby another vessel) to actuate. Signals produced by various sensors onthe one or more streamers are ultimately conducted to the recordingequipment, where a record with respect to time is made of the signalsproduced by each sensor (or groups of such sensors). The recordedsignals are later interpreted to infer the structure and composition ofthe Earth formations below the bottom of the body of water.

The one or more streamers are in the most general sense long cables thathave seismic sensors disposed at spaced apart positions along the lengthof the cables. A typical streamer can extend behind the seismic vesselfor several kilometers. Because of the great length of the typicalstreamer, the streamer may not travel entirely in a straight line behindthe seismic vessel at every point along its length due to interaction ofthe streamer with the water and currents in the water, among otherfactors.

The quality of images of the Earth's subsurface produced from threedimensional seismic surveys is affected by how well the positions of theindividual sensors on the streamers are known and controlled. Thequality of images generated from the seismic signals also depends to anextent on the relative positions of the seismic receivers beingmaintained throughout the seismic survey. Various devices are known inthe art for positioning streamers laterally and/or at a selected depthbelow the water surface. U.S. Pat. No. 5,443,027 issued to Owsley etal., for example, describes a lateral force device for displacing atowed underwater acoustic cable that provides displacement in thehorizontal and vertical directions. The device has a hollow spool and arotationally mounted winged fuselage. The hollow spool is mounted on acable with cable elements passing therethrough. The winged fuselage ismade with the top half relatively positively buoyant and the bottom halfrelatively negatively buoyant. The winged fuselage is mounted about thehollow spool with clearance to allow rotation of the winged fuselage.The difference in buoyancy between the upper and lower fuselagemaintains the device in the correct operating position. Wings on thefuselage are angled to provide lift in the desired direction as thewinged fuselage is towed through the water. The device disclosed in theOwsley et al. patent provides no active control of direction or depth ofthe streamer, however.

U.S. Pat. No. 6,011,752 issued to Ambs et al. describes a seismicstreamer position control module having a body with a first end and asecond end and a bore therethrough from the first end to the second endfor receiving a seismic streamer. The module has at least one controlsurface, and at least one recess in which is initially disposed the atleast one control surface. The at least one control surface is movablyconnected to the body for movement from and into the at least one recessand for movement, when extended from the body, for attitude adjustment.Generally, the device described in the Ambs et al. patent is somewhatlarger diameter, even when closed, than the streamer to which it isaffixed, and such diameter may become an issue when deploying andretrieving streamers from the water.

U.S. Pat. No. 6,144,342 issued to Bertheas et al. describes a method forcontrolling the navigation of a towed seismic streamer using “birds”affixable to the exterior of the streamer. The birds are equipped withvariable-incidence wings and are rotatably fixed onto the streamer.Through a differential action, the wings allow the birds to be turnedabout the longitudinal axis of the streamer so that a hydrodynamic forceoriented in any given direction about the longitudinal axis of thestreamer is obtained. Power and control signals are transmitted betweenthe streamer and the bird by rotary transformers. The bird is fixed tothe streamer by a bore closed by a cover. The bird can be detachedautomatically as the streamer is raised so that the streamer can bewound freely onto a drum. The disclosed method purportedly allows thefull control of the deformation, immersion and heading of the streamer.

Systems for determining relative positions of seismic streamers in thewater are disclosed, for example, in U.S. Pat. No. 7,376,045 issued toFalkenberg et al. (“the '045 patent”) and assigned to the assignee ofthe present invention. A system disclosed in the '045 patent includes aplurality of acoustic transmitters, mounted inside the streamers,adapted to transmit broadband signals having low cross-correlationbetween the signals of different transmitters; a plurality of acousticreceivers, mounted inside the streamers, adapted to receive the signalsfrom the transmitters; at least one processor adapted to cross-correlatethe signals received at the receivers with copies of transmitter signalsto determine identities of the transmitters of the received signals andto determine travel times of the received signals; and a main processoradapted to convert the travel times to distances between the identifiedtransmitters and the receivers and to determine relative positions ofthe streamers from the distances.

There continues to be a need for devices and methods for marine seismicstreamers to determine and/or maintain depth and heading of thestreamers along their length in order to improve the quality of seismicsurveys.

SUMMARY OF THE INVENTION

A method for marine seismic surveying according to one aspect of theinvention includes determining at least an initial depth of a pluralityof spaced apart seismic sensors on streamers towed in a body of water.The sensors each include a substantially collocated pressure responsivesensor and motion responsive sensor. A ghost time delay is determinedfor each sensor based on the at least an initial depth. Seismic signalsdetected by each motion responsive sensor and each pressure responsivesensor are cross ghosted. The at least initial depth is adjusted, andthe determining ghost time delay and cross ghosted seismic signals arerepeated until a difference between the cross ghosted motion responsivesignal and the cross ghosted pressure responsive signal falls below aselected threshold.

Other aspects and advantages of the invention will be apparent from thefollowing description and the appended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows an example “dual sensor” marine seismic acquisition systemhaving lateral force and depth (“LFD”) control devices in accordancewith an embodiment of the invention.

FIG. 2 shows an oblique view of one of the LFD control devices affixedto a streamer in accordance with an embodiment of the invention.

FIG. 3 shows a plan view of a system such as shown in FIG. 1 includingacoustic devices for determining relative positions of the sensors inthe streamers in accordance with an embodiment of the invention.

FIG. 4 shows an example of seismic energy being emitted and detected byvarious sensors on one of the streamers shown in FIG. 1 to illustrate aprinciple of the invention.

FIG. 5 shows a flow chart of an example method in accordance with anembodiment the invention.

FIG. 6 shows an example computer apparatus which may be used forprocessing data within the recording system in accordance with anembodiment of the invention.

DETAILED DESCRIPTION

FIG. 1 shows an example of a marine seismic survey system in accordancewith an embodiment of the invention. The marine seismic survey systemincludes a seismic vessel 10 that moves along the surface of a body ofwater 11 such as a lake or the ocean. The seismic vessel 10 may includethereon certain equipment, shown at 12 and for convenience collectivelycalled a “recording system.” The recording system 12 typically includesa data recording unit (not shown separately) for making a record,typically indexed with respect to time, of signals generated by variousseismic sensors (explained below) in the acquisition system. Therecording system 12 also typically includes navigation equipment (notshown separately) to determine at any time the position of the vessel 10and each of a plurality of seismic sensors 22 disposed at spaced apartlocations on streamers 20 towed by the vessel 10. The recording system12 may include devices (not shown separately) for selective actuation ofa seismic energy source or array of such sources, as will be furtherexplained with reference to FIG. 3. The foregoing elements of therecording system 12 are familiar to those skilled in the art and are notshown separately in the figures herein for clarity of the illustration.

The seismic sensors 22 can each be a combination of seismic sensorsknown in the art. In accordance with an embodiment of the invention,each seismic sensor may comprise a dual sensor including a directionalsensor, such as a motion responsive sensor or acceleration sensor,substantially collocated with a non-directional sensor, such as apressure sensor or pressure time gradient sensor. Examples of suchsensors and streamers made therewith are described in U.S. Pat. No.7,239,577 issued to Tenghamn et al. and assigned to the assignee of thepresent invention. The seismic sensors 22 measure seismic energyprimarily reflected from various structures in the Earth's subsurfacebelow the bottom of the water 11. The seismic energy originates from aseismic energy source (FIG. 3) deployed in the water 11. The seismicenergy source (FIG. 3) may be towed in the water 11 by the seismicvessel 10 or by a different vessel (not shown).

In the seismic survey system shown in FIG. 1, there are four seismicsensor streamers 20 towed by the seismic vessel 10. The number ofseismic sensor streamers may be different in other examples; therefore,the number of streamers such as shown in FIG. 1 is not a limit on thescope of the present invention. As explained in the Background sectionherein, in seismic acquisition systems such as shown in FIG. 1 thatinclude a plurality of laterally spaced apart streamers, the streamers20 are coupled to towing equipment that secures the forward ends of thestreamers 20 at selected lateral positions with respect to each otherand with respect to the seismic vessel 10. As shown in FIG. 1, thetowing equipment can include two paravane tow ropes 8 each coupled tothe vessel 10 at one end through a winch 19 or similar spooling devicethat enables changing the deployed length of each paravane tow rope 8.The distal end of each paravane tow rope 8 is functionally coupled to aparavane 14. The paravanes 14 are each shaped to provide a lateralcomponent of motion to the various towing components deployed in thewater 11 when the paravanes 14 are moved through the water 11. Thelateral motion component of each paravane 14 is opposed to that of theother paravane 14, and is generally in a direction transverse to thecenterline of the vessel 10. The combined lateral motion of theparavanes 14 separates the paravanes 14 from each other until they putinto tension one or more spreader ropes or cables 24, functionallycoupled end to end between the paravanes 14.

The streamers 20 are each coupled at the axial end thereof nearest thevessel 10 to a respective lead-in cable termination 20A. The lead-incable terminations 20A are coupled to or are associated with thespreader ropes or cables 24 so as to fix the lateral positions of thestreamers 20 with respect to each other and with respect to the vessel10. Electrical and/or optical connection between the appropriatecomponents in the recording system 12 and, ultimately, the sensors 22(and/or other circuitry) in the ones of the streamers 20 inward of thelateral edges of the system may be made using inner lead-in cables 18,each of which terminates in a respective lead-in cable termination 20A.A lead-in termination 20A is disposed at the vessel end of each streamer20. Corresponding electrical and/or optical connection between theappropriate components of the recording unit 12 and the sensors in thelaterally outermost streamers 20 may be made through respective lead-interminations 20A, using outermost lead-in cables 16. Each of the innerlead-in cables 18 and outermost lead-in cables 16 may be deployed by arespective winch 19 or similar spooling device such that the deployedlength of each cable 16, 18 can be changed.

The system shown in FIG. 1 may also include a plurality of LFD controldevices 26 cooperatively engaged with each of the streamers 20 atselected positions along each streamer 20. Each LFD control device 26can include rotatable control surfaces (FIG. 2) that when moved to aselected rotary orientation with respect to the direction of movement ofsuch surfaces through the water 11 creates a hydrodynamic lift in aselected direction to urge the streamer 20 in any selected directionupward or downward in the water 11 or transverse to the direction ofmotion of the vessel. Thus, the LFD control devices 26 can be used tomaintain the streamers 20 in a selected geometric arrangement. The LFDcontrol devices 26 may be operated by command signals generated in therecording system 12 in response to control inputs that will be furtherexplained below.

FIG. 2 shows an oblique view of one example of the LFD control devices26 as it is coupled to a streamer 20 in accordance with an embodiment ofthe invention. As will be appreciated by those skilled in the art, atypical streamer is formed by coupling together end to end a pluralityof streamer segments. Each streamer segment includes terminations ateach longitudinal end. Each such termination may be coupled to acorresponding termination at one longitudinal end of another suchstreamer segment. The terminations typically include electrical and/oroptical couplings to enable power and/or signal communication betweenelectrical and/or optical cables disposed in each streamer segment. Theterminations also include a feature for coupling the termination to oneor more strength members in each streamer segment and thus transmitaxial load from one streamer segment to the next through theinterconnected terminations. In the present embodiment, the LFD controldevice 26 forms a coupling that may be disposed between the terminationsof two streamer segments. The LFD control device 26 may include an outerhousing 32 rotatably affixed to an inner housing 30. An outer housing 32may include about its circumference four, substantially orthogonallydisposed control surfaces 34, 36 and 38. The control surfaces 34, 36, 38may be planar, or may have a generally airfoil shaped cross section toreduce turbulence as the LFD control device 26 is moved through thewater (11 in FIG. 1). The control surfaces 34, 36, 38 may be coupled tothe outer housing 32 using quick connects 40. The quick connects 40provide the system user with the ability to rapidly install and removeall the control surfaces 34, 36, 38 from the outer housing 32 duringdeployment and retrieval of a streamer having such LFD control devices26 included therein. The outer housing 32 includes therein devices (notshown) that cause the control surfaces 34, 36, 38 to rotate about axesthat may be substantially perpendicular to the longitudinal axis of theouter housing 32 and in the plane of each control surface 34, 36, 38.

In the present example, the control surface 36 shown in the uppermostposition may be positively buoyant. The control surface 38 shown in thelowermost position may be negatively buoyant. The two control surfaces34 shown in approximate horizontal orientation may be substantiallyneutrally buoyant. Such arrangement of buoyancy of the various controlsurfaces 34, 36, 38 provides that the outer housing 32 will remainsubstantially in the rotary orientation shown in FIG. 2 notwithstandingthe effects of torque on the streamer during operation that may causethe inner housing 30 to rotate correspondingly.

FIG. 2 shows the control surfaces of the LFD 26 in a neutral position,wherein the plane of each control surface is substantially along thedirection of motion of the streamer through the water. Rotation of thevertically oriented control surfaces 36, 38 may be used to affectlateral direction of the streamer, and rotation of the horizontallyoriented control surfaces 34 may be used to affect the depth (verticaldirection) of the streamer.

In some implementations, the dimensions of the inner housing 30 andouter housing 32 are selected such that when the control surfaces 34,36, 38 are removed using the quick connects 40, the external diameter ofthe outer housing 32 is about the same as that of the streamer 20. TheLFD devices 26 may be used in some examples, explained in more detailbelow, to adjust the array geometry.

FIG. 3 is a plan view of a different example seismic acquisition, inwhich devices for determining positions of the towed marine seismicstreamers are included, in accordance with an embodiment of theinvention. As in FIG. 1, above, a seismic survey vessel 10 tows devicesin the water including a seismic energy source consisting of air gunarrays 2, and a spread of four streamers 20. The streamers 20 extendfrom paravanes 14 at the front of the spread to tail buoys 5 at therear. GPS receivers (not shown separately) may be located on the vessel10, on the paravanes 14 and on tail buoys 5, to receive signals fromnavigation satellites 6 in space and provide accurate geodetic positionsof certain reference points in the system.

The streamer position determining system further comprises a number ofacoustic transmitters 9 and receivers 21 mounted inside the sections(not designated here) of the streamers 20. The acoustic transmitters 9and receivers 21 communicate with a main processor in the recordingsystem 12 via an electrical and/or cable bundle within the streamers 20.The main processor is typically located in the recording system 12onboard the survey vessel 10, although this location should not beconsidered a limitation of the invention. A transmitter 9 and a receiver21 may be combined in one transducer unit, although this combinationshould not be considered a limitation of the invention. If thetransmitter 9 and receiver 21 are combined into one transducer unit,then this transducer unit can act as either a transmitter 9 or areceiver 21 or even both (although not simultaneously). Any or all ofthe acoustic receivers 21 may be configured to measure absolute pressurein the water as well as to detect signals from the transmitters 9, orseparate pressure sensors may be included in the streamers proximateeach of the seismic sensors (22 in FIG. 1) to determine the depth ofeach of the seismic sensors in the water.

In one example the acoustic system for determining streamer positionstransmits signals within the frequency range of 10 kHz to 40 kHz. Thisfrequency band is selected to avoid signal degradation in hostileacoustic environments that occurs when higher ultrasonic frequencies areutilized and the decreased signal resolution that occurs when lowerfrequencies are utilized. The transmitters 9 transmit an acoustic signalin the water and the receivers 11 receive these transmitted signals.Several transmitters 9 may transmit at the same time, but differenttransmitters 9 transmit different signals. The different signals fromdifferent transmitters have low cross correlation, so that a receiver 11can distinguish between different transmitter signals even if thesignals arrive simultaneously. The foregoing components of a streamerlocation system are described more fully in U.S. Pat. No. 7,375,045issued to Falkenberg et al. and assigned to the assignee of the presentinvention. Use of a system for determining position as described hereinmay provide improved results for a method according to the invention aswill be further explained below, however the use of such positiondetermining system is not a limit on the scope of the invention.

FIG. 4 shows an example of the acquisition of marine seismic data inaccordance with an embodiment of the invention. The seismic vessel 101moves along the surface 108 of a body of water 102 above a portion 103of the subsurface that is to be surveyed. Beneath the water bottom 104,the portion 103 of the subsurface contains rock formations of interestsuch as a layer 105 positioned between an upper boundary 106 and lowerboundary 107 thereof. The seismic vessel 101 contains seismicacquisition control equipment, designated generally at 109. The seismicacquisition control equipment 109 includes navigation control, seismicenergy source control, seismic sensor control, and signal recordingequipment, all of which can be of types well known in the art.

The seismic acquisition control equipment 109 causes a seismic source110 towed in the body of water 102 by the seismic vessel 101 (or by adifferent vessel) to actuate at selected times. The seismic source 110may be of any type well known in the art of seismic acquisition,including air guns or water guns, or particularly, arrays of air guns.Seismic streamers 111 are also towed in the body of water 102 by theseismic vessel 101 (or by a different vessel) to detect the acousticwavefields initiated by the seismic source 110 and reflected frominterfaces in the environment. Only one seismic streamer 111 is shown inFIG. 4 for illustrative purposes. As shown in FIG. 1 and FIG. 3,typically a plurality of laterally spaced apart seismic streamers 111are towed behind the seismic vessel 10. In the present example theseismic streamers 111 contain pressure responsive sensors such ashydrophones 112, and water particle motion responsive sensors such asgeophones 113. The hydrophones 112 and geophones 113 are typicallyco-located in pairs or pairs of sensor arrays at regular intervals alongthe seismic streamers 111.

Each time the seismic source 110 is actuated, an acoustic wavefieldtravels in spherically expanding wave fronts. The propagation of thewave fronts will be illustrated herein by ray paths which areperpendicular to the wave fronts. An upwardly traveling wavefield,designated by ray path 114, will reflect off the water-air interface atthe water surface 108 and then travel downwardly, as in ray path 115,where the wavefield may be detected by the hydrophones 112 and geophones113 in the seismic streamers 111. Such a reflection from the watersurface 108, as in ray path 115 contains no useful information about thesubsurface formations of interest. However, such surface reflections,also known as ghosts, act as secondary seismic sources with a time delayfrom initiation of the seismic source 110.

The downwardly traveling wavefield, in ray path 116, will reflect offthe earth-water interface at the water bottom 104 and then travelupwardly, as in ray path 117, where the wavefield may be detected by thehydrophones 112 and geophones 113. Such a reflection at the water bottom104, as in ray path 117, contains information about the water bottom104. Ray path 117 is an example of a “primary” reflection, that is, areflection originating from a boundary in the subsurface. The downwardlytraveling wavefield, as in ray path 116, may transmit through the waterbottom 104 as in ray path 118, reflect off a layer boundary, such as107, of a layer, such as 105, and then travel upwardly, as in ray path119. The upwardly traveling wavefield, ray path 119, may then bedetected by the hydrophones 112 and geophones 113. Such a reflection offa layer boundary 107 contains useful information about a formation ofinterest 105 and is also an example of a primary reflection.

The acoustic wavefields will continue to reflect off interfaces such asthe water bottom 104, water surface 108, and layer boundaries 106, 107in combinations. For example, the upwardly traveling wavefield in raypath 117 will reflect off the water surface 108, continue travelingdownwardly in ray path 120, may reflect off the water bottom 104, andcontinue traveling upwardly again in ray path 121, where the wavefieldmay be detected by the hydrophones 112 and geophones 113. Ray path 121is an example of a multiple reflection, also called simply a “multiple”,having multiple reflections from interfaces. Similarly, the upwardlytraveling wavefield in ray path 119 will reflect off the water surface108, continue traveling downwardly in ray path 122, may reflect off alayer boundary 106 and continue traveling upwardly again in ray path123, where the wavefield may be detected by the hydrophones 112 andgeophones 113. Ray path 123 is another example of a multiple reflection,also having multiple reflections in the subterranean earth.

For purposes of the following explanation, the terms “hydrophone” and“geophone” will be used as shorthand descriptions for the types ofsignals being processed. It is to be clearly understood that the term“hydrophone” in the following description is intended to mean signalsdetected by any form of pressure responsive or pressure time gradientresponsive sensor. Correspondingly, “geophone” signals are intended tomean signal detected by any form of particle motion responsive sensor,including accelerometers, velocity meters and the like.

A method according to an embodiment of the invention begins using therecorded hydrophone and geophone signals corresponding to each actuationof the source. The recordings may be compensated for their respectivesensor and recording channels' impulse responses and the transductionconstant of each type of sensor used. Each such record of hydrophone andgeophone recordings corresponding to a particular actuation of thesource may be referred to as a “common shot” record or common shot“gather.” The signal recordings may be indexed with respect to time ofactuation of the seismic source, and may be identified by the geodeticposition of each seismic sensor at the time of recording. The geophonesignals may be normalized with respect to the angle of incidence of theseismic wave front detected by each geophone. See, for example, U.S.Pat. No. 7,359,283 issued to Vaage et al. and assigned to an affiliateof the assignee of the present invention for a description of suchnormalization. The hydrophone response is substantially omni-directionaland typically does not require correction or normalization for angle ofincidence. A correction filter, w, may be determined to cause thehydrophone impulse response h and the geophone impulse response g tosubstantially match as in the following expression:h=g*w  (1)

In a practical implementation of a method, the normalized common-shotrecords may be transformed from the time-position domain (where positionrepresents the geodetic position of each sensor at the time of signalrecording) into the frequency-wavenumber (f−k) domain. The resultingdomain-transformed signals may be represented by the followingmathematical expressions:H=hP _(up)(1−Z)G=gP _(up)(1+Z)  (2)where H represents the f−k transform of the hydrophone signals, Grepresents the f−k transform of the geophone signals, h is thehydrophone impulse response, and g is the geophone impulse response.P_(up) represents the upwardly propagating pressure wave field, Zrepresents the frequency-domain time delay operator:Z=exp[2πif(2z cos φ)v)]  (3)in which i is the imaginary number √−1, f represents the seismic energyfrequency, z represents the sensor depth in the water, φ represents theangle of incidence of the seismic energy at the sensor, and v representsseismic velocity in the water. The seismic energy frequency f, the angleof incidence of the seismic energy at the sensor φ, and the seismicvelocity v may be determined from the sensor data. The quantities (1+Z)and (1−Z) represent the geophone and hydrophone “ghosting” functions,respectively. The time delay and the respective ghosting functions arerelated to the depth of each seismic sensor and the velocity of seismicenergy in the water if it is known or is readily determinable. Thepresent example includes transformation of the hydrophone and geophonesignals into the frequency-wavenumber domain in particular to facilitatecalculating the geophone and hydrophone ghosting functions. It is to beunderstood that other implementations may process the signals other thanin the frequency-wavenumber domain.

In a method according to the invention, the hydrophone signals and thegeophone signals are cross ghosted using expressions such as thefollowing in which # denotes a cross ghosted signal:H#=H(1+Z) and G#=w G(1−Z)  (4)

If the values of w and z are correct, then the cross ghosted geophoneand hydrophone signals will be substantially equal, and their differencewill be substantially zero:H#=G4 and H™−G#=0  (5)

Assuming, for example, that either the sensor depth z or calibrationfilter w is not correct, then:H#′=H(1+Z′) and G#′=w′G(1−Z′)  (6)

Where Z′ corresponds to the ghost time delay at the incorrect depth, andw′ is the incorrect calibration. In such case the difference H#′−G#′will not be equal to zero. In the present example, a value of w may beperturbed or varied, and a value of z for each seismic sensor (22 inFIG. 1) may be perturbed or varied, and values of Z may be calculatedusing equation (2). The foregoing perturbed values may be used inequation (3) to determine cross ghosted signals using the perturbedvalues. The foregoing process is repeated until values of w and z aredetermined such that the difference between the calculated cross ghostedsignals, H#−G#, reaches a minimum. The values of depth of each sensor zso determined may be used as the correct depth of each sensor indetermining the geometry of the sensor array.

In other examples, in addition to calculating a sensor depth for eachsensor as explained above, the relative positions of the sensors withrespect to each other (e.g., the plan view shown in FIG. 1) may bedetermined by perturbing the angle of incidence of the seismic energy ateach sensor and recalculating the cross ghosting time delay function Zusing equation (3). Differences between the cross ghosted sensorresponses calculated as explained above may be determined, and theperturbing of positions, calculating of cross ghosting time delayfunction and determining difference may be repeated until differencesbetween the cross ghosted signals are minimized.

In some examples, signals from the acoustic position determining system(FIG. 3) may be used to initialize the x and y values of the relative(lateral) position of each seismic sensor and the depth z thereof inperforming the procedure explained above. The lateral position of eachseismic sensor may be relative to a reference point in the acquisitionsystem which may be, for example, on the vessel 10 or within the spreadof streamers 20.

In another example, the determined relative positions and depths may beused as input control signals to operate the LFD devices (26 in FIG. 1)to cause the sensor depths and relative positions to be optimized ornormalized. In some examples, the LFD devices may be operated to adjustthe actual depth and/or the actual lateral positions of the seismicsensors so that the difference between the cross ghosted signals at eachsensor is minimized or falls below a selected threshold.

A flow chart showing the elements of an example method according to anembodiment of the invention is shown in FIG. 5. At 50, values for eachseismic sensor, including a value for a depth z, a correction filter w(which may be referred to as a calibration factor and causes matching ofthe geophone and hydrophone impulse response signals, as discussedabove), and relative lateral positions x, y may be initialized. Asexplained above, data to initialize the foregoing x, y and z values maybe obtained from the various components and known dimensions of theposition determination system (FIG. 3). For example, the initial valuefor the depth z for each sensor may be determined from a measurement ofpressure at the sensor. The correction filter w may be initialized to anapproximate function or value based on impulse response measurements ofthe sensors. At 52, values of the ghost time delay function Z may becalculated for each seismic sensor. At 54, values of the cross ghostedhydrophone and geophone signals, H# and G#, respectively may becalculated for each seismic sensor using the foregoing values of Z. At56, a difference between the cross ghosted signals is determined foreach seismic sensor. If the cross ghosted seismic signal differences areat a minimum, at 60, then the correct values of z, w, x and y have beendetermined for each seismic sensor. If the differences are not at aminimum, then at 58, one or more of the values of z, w, x and y may beperturbed or adjusted, and the process may return to calculation of Zusing the perturbed value(s). The foregoing may be repeated until thedifference between the cross ghosted signals reaches a minimum or fallsbelow a selected threshold.

In accordance with an embodiment of the invention, the value for thedepth z, the correction filter w, and the position values (x, y) for thelateral positions for each of the plurality of seismic sensors may eachbe periodically adjusted. This may be accomplished by periodicallyperforming the above discussed method starting at step 52 until thedifference between cross ghosted signals is minimized and the correct z,w, x, and y are determined per step 60. Such periodic adjustment may beused advantageously to track changes in the geometry of the sensor arrayas the depths and relative positions of the seismic sensors vary overtime during the seismic survey.

Methods according to the invention may provide better determination ofsensor position in a seismic sensor array than is possible usingtechniques known in the art. Methods according to the invention mayprovide more precise control over the position of seismic sensors in anarray when used in conjunction with active streamer positioning controldevices.

FIG. 6 shows an example computer apparatus which may be used forprocessing data within the recording system in accordance with anembodiment of the invention. The computer apparatus 600 may beconfigured with executable instructions so as to perform the dataprocessing methods described herein. This figure shows just one exampleof a computer which may be used to perform the data processing methodsdescribed herein. Many other types of computers may also be employed,such as multi-processor computers, server computers, cloud computing viaa computer network, and so forth.

The computer apparatus 600 may include a processor 601, such as thosefrom the Intel Corporation of Santa Clara, Calif., for example. Thecomputer apparatus 600 may have one or more buses 603 communicativelyinterconnecting its various components. The computer apparatus 600 mayinclude one or more user input devices 602 (e.g., keyboard, mouse), oneor more data storage devices 606 (e.g., hard drive, optical disk, USBmemory), a display monitor 604 (e.g., LCD, flat panel monitor, CRT), acomputer network interface 605 (e.g., network adapter, modem), and amain memory 610 (e.g., RAM).

In the example shown in this figure, the main memory 610 includesexecutable code 612 and data 614. The executable code 612 may comprisecomputer-readable program code (i.e., software) components which may beloaded from the data storage device 606 to the main memory 610 forexecution by the processor 601. In particular, the executable code 612may be configured to perform the data processing methods describedherein.

While the invention has been described with respect to a limited numberof embodiments, those skilled in the art, having benefit of thisdisclosure, will appreciate that other embodiments can be devised whichdo not depart from the scope of the invention as disclosed herein.Accordingly, the scope of the invention should be limited only by theattached claims.

What is claimed is:
 1. A method for using a marine seismic surveyingsystem using towed multi-component streamers including a plurality ofseismic sensors which are spaced apart, the method comprising:determining at least a value for a depth of each of the plurality ofseismic sensors in a body of water, the seismic sensors each including apressure responsive sensor and a motion responsive sensor; determining aghost time delay based on at least the value for the depth; crossghosting seismic signals detected by each motion responsive sensor andeach pressure responsive sensor to obtain a cross ghosted motionresponsive signal and a cross ghosted pressure responsive signal,wherein the cross ghosting uses a calibration factor for each seismicsensor; computing a difference between the cross ghosted motionresponsive signal and the cross ghosted pressure responsive signal foreach of the seismic sensors; adjusting at least the value for the depthof each of the seismic sensors based on the difference; repeatingdetermining the ghost time delay, cross ghosting the seismic signals,and computing the difference; and repeating the adjusting at least thevalue for the depth, determining the ghost time delay, cross ghostingthe seismic signals, and computing the difference until the differencefalls below a selected threshold, wherein the method is performed duringoperation of the marine seismic survey system.
 2. The method of claim 1,wherein determining the value for the depth comprises measuring pressureat each seismic sensor.
 3. The method of claim 1 further comprising:determining an initial factor for the calibration factor each seismicsensor, wherein adjusting at least the value for the depth of eachseismic sensor includes adjusting the calibration factor based on thedifference between the cross ghosted signals.
 4. The method of claim 3,wherein a motion-responsive impulse response shaped by a correctionfilter substantially matches a pressure-responsive impulse response. 5.The method of claim 1 further comprising: determining position valuesfor a lateral position of each seismic sensor, wherein adjusting atleast the value for the depth of each seismic sensor includes adjustingthe position values for the lateral position of each seismic sensor. 6.The method of claim 5, further comprising: operating lateral controldevices to perform lateral movement of the seismic sensors; computingthe difference for each seismic sensor after said lateral movement; anddetermining whether the difference for each seismic sensor is therebyreduced.
 7. The method of claim 1, further comprising: periodicallyadjusting the value for the depth of each of the plurality of seismicsensors so that the difference falls below the selected threshold. 8.The method of claim 1, further comprising: periodically adjusting thevalue for the depth and position values for the lateral position of eachof the plurality of seismic sensors so that the difference falls belowthe selected threshold.
 9. The method of claim 1, further comprising:periodically adjusting the value for the depth, position values for thelateral position, and the calibration factor of each of the plurality ofseismic sensors so that the difference falls below the selectedthreshold.